Apparatus for use when gathering parameters from a well flow and also a method of using same

ABSTRACT

An apparatus ( 3 ) for use when gathering parameters from a well flow in a petroleum well ( 1 ) in order to be able to evaluate the flow and productivity or injectivity of the well is described, the apparatus ( 3 ) including: —a semi-rigid rod ( 5 ) arranged in a manner allowing it to sense the temperature profile of the well ( 1 ); —at least two mutually spaced-apart measuring devices and/or fluid phase indicators ( 9 ) attached to the semi-rigid rod ( 5 ); and —at least one pressure sensor ( 11 ) arranged in a manner allowing it to sense pressure in the well ( 1 ), whereby the amounts of water, oil and gas from one or more formation sections may be quantified. A method of using the apparatus is also described.

The present invention relates to an apparatus for, and a method of, gathering parameters from a well flow. More particularly, it relates to an apparatus and a method for gathering parameters along a petroleum well path in order thus to be able to evaluate the flow, fluid phases and productivity or injectivity of the well.

In the oil and gas production industry, there is a need for being able to evaluate petroleum wells producing oil and/or gas and/or water in order to measure the inflow of oil, gas and water along well paths above the reservoir section from which oil, gas and water are produced. This is particularly challenging in horizontal wells, including both a horizontal branch and so-called multiple branches or multilaterals.

Several apparatuses and methods for gathering data from a well are known for allowing evaluation of pressure and flow, and for allowing estimation of the fluid phases of the well flow, and the productivity or injectivity of the well.

A familiar method is to install required sensors permanently along predetermined locations in the well path. The sensors communicate to the surface, for example to a rig, through one of, or a combination of, two or more of an electrical cable or a fibre cable. Data can also be communicated to the surface by means of wireless communication, or by means of so-called memory cards temporarily storing the gathered data in the well.

Electricity for electronic sensors is provided by means of batteries, or by means of cable to an energy source at the surface.

In order to be able to gather data from a well, it is also known to insert required sensors into the well, for example by means of a cable or so-called wireline, or by means of coiled tubing.

There are several disadvantages related to the above-mentioned prior art.

When using permanently installed sensors, the placement thereof must be planned and installed before being inserted into the well. The additional rig time required to install the sensors depends on the number of cables to be fitted, the number of sensor units to be fitted/installed, and on the length of the well. Experience goes to show that it is very costly to install sensors on a permanent basis in a well.

Among other things, electronic units have proven very vulnerable to the high temperatures that might exist in a well, and also to impacts and shocks. Electronic sensors therefore have a limited operating time. Replacement of failed electronic sensors is both time-consuming and difficult.

With respect to space in the well between a production tubing and a casing, passages for cables onward to the surface, and the clamping of a cable to the production tubing, permanently installed systems represent a challenge to the completion of wells.

Within the industry, downhole monitoring is considered to represent a high degree of difficulty. This particularly applies to wells having well path angles between 65° and 95°.

In order to reduce the above-mentioned disadvantages represented by the permanently installed monitoring- or logging systems, sensors may be inserted into the well after having been established.

In order to insert logging systems into wells having high well path angles, i.e. well paths having an angle between 65° and 95°, coiled tubing or wireline with a well tractor is required.

Coiled tubing, however, has a tendency to “buckle”, i.e. it is coils up and assumes the shape of a helical spring so as to stop, or it winds (becomes “helical”), i.e. the tubing assumes the shape of a helical spring so as not to stop. This is particularly a problem experienced upon repeated use of the coiled tubing. To remedy this problem, among other things, well tractors for coiled tubing have been developed. However, coiled tubing in the well will cause the effective pipe diameter to become reduced, and the production of the fluid to become slowed down due to increased friction between the production tubing and the coiled tubing. This friction results in the well not behaving in an optimum manner, and in some cases the result of the logging does not represent a correct image of the flow conditions within the well.

Additionally, coiled tubing has a limited reach, insofar as there is a limit to how much coiled tubing may be reeled onto a drum to be used, for example, from a rig or a ship.

Wireline requires a well tractor to push the logging tool in front of itself. A well tractor may also function as a throttle unit (choke). In some cases, it has been produced out of a horizontal well as a consequence of the production rate being too high.

In some cases, this has resulted in the cable, which connects the well tractor to the surface, to become twisted. Such a situation has resulted in equipment being lost in the well in response to the cable being ruptured during attempts of retrieving the equipment from the well.

It is also possible for a well tractor to get stuck in, for example, grooves in the well. This may result in not being able to retrieve the well tractor and the logging tool, instead being left in the well. Getting stuck with the well tractor has proven especially problematic in wells having valves or so-called “sleeves”, and in well paths without any casing, so-called “open-hole solutions”. Purpose-built well tractors for use in open-hole solutions have been developed, but they involve the same type of throttling problem as mentioned above.

All types of logging involving insertion of the logging tools into the well by means of coiled tubing or wireline, require movement into and out of the well during production, and under so-called shut-in well conditions. During such movements, the sensors may stop functioning in the intended manner.

High temperatures in the well, for example above 140° C., oftentimes lead to problems related to reduced strength or loss of electrical signal in the transitional portion between the cable and the logging tool. Experience goes to show that pressure—and temperature data generally experience a lot of noise under such conditions, which may result in unreliable data from the well.

Logging with a fibre cable is limited to the ability to measure temperature along the cable. As of today, flow can be measured only in permanently installed solutions in which fibre cables are used (and simultaneously are installed along the well path above the reservoir section), and both pressure and flow must be measured to evaluate the productivity or injectivity of the well. As of today, there are no logging sensors available for rigid fibre cable or semi-rigid rod capable of measuring the fluid phases of the well flow or capable of differentiating oil, water and gas in a well flow.

The object of the invention is to remedy or reduce at least one of the disadvantages of the prior art.

The object is achieved through features disclosed in the description below and in the subsequent claims.

In the method according to the present invention, a measuring device is run into a desired portion of a well by means of a thin, rigid cable, hereinafter referred to as a semi-rigid rod. The well path may be both vertical and horizontal. The measuring devices are arranged for providing data for allowing estimation of the fluid phases oil, gas and water in the well flow, and to be able to provide data for allowing estimation of the productivity index, PI, or injectivity index, II, of the well. A person skilled in the art will know that the well's productivity index PI, or injectivity index II, represents flow rate per day per unit of pressure, for example BBL/d/psi. The corresponding term for the injectivity index II will be injection rate per day per unit of pressure, for example BBL/D/psi.

The sensors may include chemicals or so-called “tracers”, which are arranged for allowing detection and quantification of fluids downhole, and also other sensor types of a type known per se.

According to the invention, temperature, so-called DTS (distributed temperature sensing), is measured along a cable or a semi-rigid rod by means of an optical-fibre cable arranged in said cable or semi-rigid rod. Thus, the semi-rigid rod forms the logging unit for the temperature profile along the well. When the temperature profile is known, the flow rate of the well may be estimated.

PCT application WO 2006/00347 describes a rod which has proven suitable for measuring DTS.

In addition to the semi-rigid rod being enable to sense temperature, pressure sensors are preferably integrated along the cable and are also placed at an end portion of a rigid fibre cable or a semi-rigid rod.

Thus, and according to the present invention, the sensors DTS, pressure and fluid identification method are combined in order to replace conventional logging methods wherein physical sensors for temperature, pressure and flow are connected as a tool string at the end of a cable.

The apparatus and method according to the present invention represent particularly great advantages in horizontal wells which otherwise cannot be logged with conventional logging tools.

According to the invention the cable is kept stationary during logging of a well under production/injection, or during logging of a shut-in well.

A person skilled in the art will appreciate that the apparatus and method according to the invention imply that there is no need for physical depth correlation tools for allowing evaluation of the log. However, a depth correlation tool may be used in connection with checking whether a rigid fibre cable or semi-rigid rod “buckles” or has become “helical”.

According to a first aspect of the present invention, an apparatus for use when gathering parameters from a well flow in a petroleum well for allowing evaluation of the flow and productivity or injectivity of the well is provided, the apparatus including:

-   -   a semi-rigid rod arranged in a manner allowing it to sense the         temperature profile of the well;     -   at least two mutually spaced-apart measuring devices and/or         fluid phase indicators attached to the semi-rigid rod; and     -   at least one pressure sensor arranged in a manner allowing it to         sense pressure in the well, whereby also the amounts of water,         oil and gas from one or more formation sections may be         quantified. When using more than two measuring devices and/or         fluid phase indicators, water, oil and gas from more than two         formation sections or zones may be quantified.

In a preferred embodiment, the at least two mutually spaced-apart measuring devices and/or fluid phase indicators include one of, or a combination of, two or more of a sensor, chemical or a trace element.

In a preferred embodiment, the semi-rigid rod includes a fibre cable. In one embodiment, the semi-rigid rod is of the type described in WO 2006/003477.

In one embodiment, the semi-rigid rod includes a plurality of spaced-apart pressure sensors.

In one embodiment, the apparatus includes an additional pressure sensor for compression-measuring of the end portion of the apparatus in the well. Preferably, the additional pressure sensor is placed between the semi-rigid rod and a so-called “bull nose” placed at the end of the apparatus in the well. The main purpose of the bull nose is to guide the semi-rigid rod past sharp edges that may be present in a well, thereby functioning as a steering device for said rod.

In a preferred embodiment, the apparatus is arranged in a manner allowing it to communicate measuring data through the fibre and out of the well while measuring is in progress.

In a second aspect of the invention, a method of gathering parameters from a well flow in a petroleum well for allowing evaluation of the flow and productivity or injectivity of the well is provided, wherein the method includes the steps of:

-   -   inserting an apparatus to a desired portion of the well, the         apparatus including:         -   a semi-rigid rod arranged in a manner allowing it to sense             the temperature profile of the well;         -   at least two mutually spaced-apart measuring devices and/or             fluid phase indicators attached to the semi-rigid rod; and         -   at least one pressure sensor arranged in a manner allowing             it to sense pressure in the well; and     -   keeping the apparatus substantially stationary within the well         during gathering of parameters from one or more formation         sections in the well.

In one embodiment, the measuring results from the measuring devices and the semi-rigid rod are communicated to the surface for further processing. Elements liberated from a chemical or a trace element may be communicated to the surface in the same manner.

An example of a preferred embodiment is described in the following and is depicted in the accompanying drawings, in which:

FIG. 1 shows a principle drawing of a well, in which measuring devices have been inserted into the well by means of a semi-rigid rod, and in which the measuring devices are comprised of the semi-rigid rod and eight sensors;

FIG. 2 a shows a graph illustrating the relationship between flow, pressure and time in a fluid-producing well.

FIG. 2 b shows a graph illustrating the relationship between flow, pressure and time in a fluid-injecting well.

A person skilled in the art will appreciate that FIG. 1 is greatly distorted, and that the relative scales of the different elements shown are incorrect.

FIG. 1 shows a principle drawing of a well 1, in which an apparatus 3 according to the present invention has been inserted into the well 1.

The apparatus 3 includes a semi-rigid rod 5 ending up, at one end portion thereof, on a reel 7 outside the well 1, and ending up, at the other end portion thereof, at a bottom portion of the well 1.

Preferably, the semi-rigid rod 5 is of a self-straightening type. That is to say, when the semi-rigid rod 5 is inserted into the well, the rod 5 has substantially no curvature remaining from the reel 7.

Disposed on the semi-rigid rod 5 are seven measuring devices in the form of six chemical devices 9 and one pressure sensor 11.

The chemical devices 9 are comprised of receptacles holding trace elements or so-called “tracers” of a type known per se. In a manner known per se, the trace elements are released into the fluid flow within which the chemical devices 9 are disposed. Preferably, the trace elements released into the fluid flow from each of the chemical devices 9 are arranged in a manner allowing them to be separated from each other.

The chemical devices 9 of FIG. 1 are attached around the semi-rigid rod 5. A person skilled in the art will appreciate that the chemical devices, in alternative embodiments, also may be arranged in a manner allowing them to be attached to, or merely be connected to, portions of the semi-rigid rod 5.

Disposed at the end of the semi-rigid rod 5 there is a so-called “bull nose” 13. As mentioned above, the main purpose is of a bull nose 13 is to guide the semi-rigid rod 5 past sharp edges that may be present in a well.

The well 1 is provided with casings/liners 15 and production tubing 17. At the end portion of the horizontal portion of the well 1, the well 1 is comprised of a so-called open hole.

The arrows in the figure illustrate the flow of fluids in through perforations 18 in the liner 15 and flow of produced fluids. A person skilled in the art will appreciate that the arrows would have pointed in the opposite direction for a fluid-injection well. The straight, broken lines illustrate the division of the formation into different zones.

Upon having placed the measuring device 3 illustrated in FIG. 1 in the well 1, it may provide the following information directly or indirectly.

Pressure within the well 1 may be measured directly by means of the pressure sensor 11, and possibly by means of pressure sensors (not shown) disposed along the rod 5.

Temperature distribution or —profile, DTS, along the semi-rigid rod 5 may be measured along the entire length thereof. Upon knowing the temperature profile, it is possible to derive a total fluid flow. From the total fluid flow, it is possible to estimate a flow profile in the well. Particular calculation models have been developed for this purpose. Preferably, the calculations are carried out by means of a computer program.

By means of the chemical devices 9 or tracers disposed along the semi-rigid rod 5, it is possible to estimate water and gas inflow points. For example, consumption of a tracers or trace elements may be determined by measuring the amount of trace elements originally installed in the chemical device 9 versus the amount remaining upon retrieving the chemical device 9 to surface after a logging operation. The consumption is a function of fluid flow rate (water, for example) past the chemical device 9 holding the trace element. Moreover, surface equipment for detecting concentrations of the different trace elements or tracers in the producing well flow may be provided.

Consumption of trace elements may also provide an indication on the direction and extent of any cross-flow in the well 1.

Upon knowing the pressure and flow of the well 1, the productivity, or the so-called productivity index PI, of the well 1 may be estimated.

When the above-mentioned information has been provided, a person skilled in the art will be able to estimate the flow contribution from each single zone or formation section in the well, so as to render possible to quantify the amounts of water, oil and gas.

A person skilled in the art will appreciate that the measuring device 3 must be kept stationary relative to the well 1 while measuring is in progress.

In the following, the main features of performing a logging operation by means of the measuring device 3 according to the present invention are described. For simplicity, some of the required features obvious to a person skilled in the art have been left out completely or partially. Similarly, the processing of the measuring results undertaken during and after the logging operation is not included either.

-   -   After having prepared the measuring device 3 on a rig or a ship,         for example, and after having shut in the well 1 by means of one         or more pressure control valves 19 in the so-called X-mas tree,         a portion of the measuring device 3 is inserted into the         so-called injection head 21. The injection head 21 is then         placed on top of said X-mas tree, and pressure control testing         is carried out.     -   Logging of the depth of the measuring tool 3 is activated by         means of a depth control unit (not shown). In its simplest form,         such a depth control unit may be comprised of a device for         measuring the length of the semi-rigid rod 5 being inserted into         the well 1, but it may also be comprised of a depth-measuring         device (not shown). Measuring results from said depth-measuring         device are compared with the measured length of the rod 5         inserted into the well 1. This makes possible to establish         whether the semi-rigid rod 5 is rigid, “buckles” or is         “helical”.     -   Having opened the pressure control valve(s) 19, the semi-rigid         rod 5 is inserted into the well 1 at a controlled speed, for         example 20 metres/min, until reaching the desired position. In         FIG. 1, the desired position is reached at the end of the well         1. Due to the inherent properties of the semi-rigid rod 5, it         will straighten out, but still adapt to the well path.     -   The measuring tool 3 is kept at rest, and logging is started         while the well 1 is shut in.     -   The well 1 is opened to a first flow denoted “flow 1” in FIG. 2,         the flow of which is assumed to be 50% of maximum flow capacity.         The well 1 is flowed towards a test separator (not shown) until         the well flow has stabilized. Experience goes to show that this         may take between six and twelve hours, however differing from         well to well. Upon assuming a stable well flow, the well 1 is         flowed for twelve hours, for example, after which logging is         performed until achieving satisfactory data quality. Any surface         sampling for analysis of trace elements being released from the         chemical devices 9 is carried out regularly, for example every         hour.     -   The well 1 is opened to a second flow depicted “flow 2” in FIG.         2, the flow of which is 100% of maximum flow capacity, and the         well is allowed to flow for another twelve hours, after which         logging is performed until achieving satisfactory data quality.         Any surface sampling for analysis of trace elements being         released from the chemical devices 9 is carried out regularly,         for example every hour.     -   The well is shut in by closing one or more pressure control         valves 19 and, if desired, pressure build-up after production is         measured. Such measuring of pressure build-up may be carried out         substantially continuously over, for example, twelve hours. Upon         finishing the logging, the apparatus 3 is retrieved from the         well 1.

FIG. 2 b shows the same procedure for a fluid-injecting well 1.

Thus, the present invention provides an apparatus which surprisingly may allow for quantification of more than one fluid phase in a well flow, simultaneously allowing measuring of the productivity or injectivity of the well.

As compared with prior art coiled tubing units, the invention will result in simpler logistics with respect to heavy lifting from, for example, a ship to a platform.

Also with respect to safety, the present invention exhibits considerable advantages relative to the prior art. Upon having run a rigid cable or semi-rigid rod in a controlled manner into the well when shut in, it will remain “parked” until the job is finished. Thus, no activity is carried out in order to move the apparatus during the operation. Any risk to personnel in the area around the logging unit is greatly reduced owing to the fact that the operation is limited only to monitoring that the signals from the fibres in the cable are of good quality. All other work takes place in an approved area, the equipment used being a PC and an interface for converting raw signals into readable data lines providing pressure, temperature, fluid phase and time indication.

Figure Text

Figure Reference FIG. 2a X-axis Time-axis Y-axis Flow-axis Brønn stengt inn Well shut in Trykkfallperioder Periods of pressure drop Trykkoppbyggings-periode Period of pressure build-up FIG. 2b Injeksjon Injection Trykkoppbyggings-perioder Periods of pressure build-up Trykkfallperiode Period of pressure drop 

1. An apparatus for use when gathering parameters from a well flow in a petroleum well for allowing evaluation of the flow and productivity or injectivity of the well continuously for a period of time, the apparatus including: a continuous, semi-rigid rod arranged in a manner allowing it to sense the temperature profile of the well; at least two mutually spaced-apart fluid phase indicators attached to the continuous, semi-rigid rod; and at least one pressure sensor arranged in a manner allowing it to sense pressure in the well, characterized in that the at least two mutually spaced-apart fluid phase indicators are disposed around the semi-rigid rod, the fluid phase indicators being arranged for detecting and quantifying the velocity and density of the fluid; and that each of the mutually spaced-apart fluid phase indicators comprise trace elements and/or chemicals that are arranged in a manner allowing them to be separated from each other, and that the fluid phase indicators are simultaneously affected by the well flow.
 2. The apparatus in accordance with claim 1, characterized in that the semi-rigid rod includes a fibre cable.
 3. The apparatus in accordance with claim 1, characterized in that the semi-rigid rod includes a plurality of spaced-apart pressure sensors.
 4. The apparatus in accordance with claim 1, characterized in that the apparatus includes an additional pressure sensor for compression-measuring of the end portion of the apparatus in the well, the additional pressure sensor being placed between the semi-rigid rod and a bull nose (13) placed at the end of the apparatus in the well.
 5. The apparatus in accordance with claim 1, characterized in that the apparatus is arranged in a manner allowing it to communicate measuring data through the fibre and out of the well while measuring is in progress.
 6. Apparatus in accordance with claim 5, characterized in that measuring data from the semi-rigid rod and elements from the fluid phase indicators are conveyed from the well independently of each other.
 7. Apparatus in accordance with claim 1, characterized in that the apparatus includes a depth-measuring device.
 8. A method of gathering parameters from a well flow in a petroleum well for allowing evaluation of the flow and productivity or injectivity of the well, characterized in that the method includes the steps of: inserting an apparatus according to claim 1 to a desired portion of the well; and keeping the apparatus substantially stationary within the well during gathering of parameters related to flow, fluid phase and pressure from one or more formation sections of the well.
 9. The method in accordance with claim 8, characterized in communicating results from the measuring devices and elements from the fluid phase indicators to the surface for further processing while the fluid phase indicators are stationary in the well.
 10. The method in accordance with claim 9, characterized in conveying measuring data from the semi-rigid rod and elements from the fluid phase indicators independently of each other from the well. 